The production of hydrocarbons (oil or gas) can be generally distilled into two primary steps—drilling a borehole to intersect hydrocarbon bearing formations or oil and gas reservoirs in the subsurface, and then completing the well in order to flow the hydrocarbons back to the surface. The ability of a well to flow hydrocarbons that are commercially significant requires that the borehole be connected to oil and gas bearing formations with sufficient permeability to support the flow rates that are needed to account for the costs of developing the field. In many instances, however, commercially viable flow rates cannot be obtained without the use of various advancements including horizontal drilling and hydraulic stimulation due to the type of formation or reservoir being developed.
More specifically, unconventional resource plays are areas where significant volumes of hydrocarbons are held in reservoirs with low primary permeability (nanodarcy to microdarcy) and low primary porosity (2-15%) such as shales, chalks, marls, and cemented sandstones that generally do not have sufficient primary permeability to yield commercial quantities of hydrocarbons. Compared to “conventional” reservoirs, unconventional reservoirs have a much lower hydrocarbon density per unit volume of rock and much lower unstimulated hydrocarbon flow rates, making commercial development impossible without hydraulic stimulation of the reservoir rock fabric. Fortunately, unconventional reservoirs are often regionally extensive covering thousands of square miles and containing billions of barrel of oil equivalent (BOE) of potentially recoverable hydrocarbons.
The economically viable production from unconventional resources has only been made possible by the improvement and combination of horizontal drilling, wellbore isolation, and hydraulic fracture stimulation treatment technologies, among other techniques. Generally speaking, horizontal drilling involves first vertically drilling down close to the top of the unconventional reservoir and then using directional drilling tools to change the orientation of the wellbore from vertical to horizontal in order to contact greater areas of the reservoir per well. The term “horizontal” drilling as used herein is meant to refer to any form of directional (non-vertical) drilling. Horizontal drilling, although having been performed for many decades prior to intensive unconventional resource development in the early 2000's, has been evolved to provide cost effective provisioning of the long horizontal borehole sections (5,000′ to 10,000+′) required to contact commercially viable volumes of hydrocarbon bearing reservoir rock. Hydraulic fracture stimulation involves pumping high volumes of pressurized fluid into the borehole and through targeted perforations in the wellbore to create large networks of cracks (fractures) in the formation that create enhanced reservoir permeability and so stimulate greater quantities of oil and gas production. Proppant is usually pumped along with the fluid to fill the fractures so permeability is maintained after the pumping is stopped and the fractures close due to reservoir stresses. Proppant can range from simple quarried sand to engineered man-made materials.
Isolation generally involves the use of some form to technology to focus where fracturing occurs at specific locations along the well bore rather than stimulating the entire length of an open wellbore. In the development of unconventional resources it is desirable to drill horizontal wells perpendicular to the direction of maximum horizontal compressive stress, because hydraulically induced fractures will grow primarily in the direction of maximum horizontal stress. When the wellbore is oriented perpendicular to the maximum horizontal compressive stress, this geometry allows for the shortest, and hence least expensive, well bore length for the volume of reservoir stimulated.
Rapidly evolving wellbore isolations techniques, such as swellable packers, sliding sleeves, and perforation cluster diversion have all assisted in reducing the cost of isolating sections of the wellbore for more targeted and more concentrated hydraulic stimulation. Hydraulic fracture stimulation has been utilized on low permeability wells for decades as well. But the use of low viscosity, simple fluids pumped in very high volumes and rates, and with large volumes of associated proppant, has been the most important aspect of contacting the greatest amount of low permeability, low hydrocarbon density reservoir rock.
Various suites of drill string or wireline conveyed well logs such as dipole sonic or natural fracture image logs can identify and quantify this variability on a scale that is useful to completions design, but existing tools are currently too expensive to run on anything but a very small fraction of unconventional wells drilled. Conventional techniques, such as dipole sonic and natural fracture image logs, are based on inferred information and not involved directly measuring the interaction of the drill bit with the formation. Instead, dipole sonic involves the transmission of acoustic signals (waves) from a controlled active acoustic source, through the rock formation in the areas of the well bore to a receiver typically several feet from the source, to measure the velocity of the waves through the formation. Natural fracture image logs involve measuring the resistivity of the formation along the walls of the wellbore. Natural fracture logs are of limited use in wells using oil based mud, which has an inherently high resistivity and masks some fractures. These techniques are often cost prohibitive and limited in effectiveness. As a result, almost all wells are completed using geometrically equal spacing of zones isolated (referred to as stages) and stimulated. Thus, for example, hydraulic fracturing is inadvertently performed routinely on individual stages with significantly varying rock properties along the isolated section, resulting in the failure to initiate induced fractures in less conducive rock and so potentially bypassing substantial volumes of hydrocarbon bearing rock. In such instances, post stimulation testing of individual zones or stages shows that a significant percentage of the hydraulically stimulated zones are not contributing to hydrocarbon production from the well. Variations in the density, size and orientation of natural fractures can have a major influence on overall well initial production, long term decline rates, and stage to stage contributions. Formation hydrocarbons are transported from the rock matrix to the producing wellbore through some combination of induced hydraulic fractures and natural occurring in-situ fractures.
Currently, less than 1% of all wells drilled and completed have suitable data to adequately quantify reservoir heterogeneity on a scale that can be used for targeting individual stimulation intervals.
It is with these observations in mind, among others, that aspects of the present disclosure have been conceived and developed.